Graphical method for assisting multi-zones commingling decision

ABSTRACT

A method and a system determine multi-zones commingling in oil field production. The system includes a processing circuitry configured to: identify a plurality of zones in a well to be analyzed based on first differences in properties or flow performance; calculate a normalized bubble point pressure; define a first bottom hole flowing pressure for the well; define flowing pressures after excluding the zone with the highest saturation pressure; calculate a normalized bottom-hole flowing pressure and a corresponding flow rate ratio; plot the flow rate ratio versus the normalized bottom-hole flowing pressure and the flow rate ratio versus the bottom-hole flowing pressure in a Cartesian scale; and determine the feasibility to produce from all the zones.

BACKGROUND

1. Field of the Disclosure

The exemplary embodiments described herein relate to a method and a system for determining multi-zones commingling in oil field.

2. Description of the Related Art

Shales and no flow layers are usually present in oil and gas reservoirs. Consequently, different zones in the reservoirs can be separated from each other. Communication between different zones depends on the dimension and permeability of the interbedded shales and sand that make up the reservoir. These reservoirs are known as “multilayered”. When the layers communicate only through the well bore, we have a commingled system. If there is some degree of communication between two or more layers, we have a cross flow system.

Most of the current reservoir discoveries have more than one pay zones from which hydrocarbons can be extracted. Although the oil companies look for the big contributor pay zones at the beginning of the production life of their fields (reservoirs), which may be one zone in some cases, the need to commingle two or more zones together is a useful technique to increase field productivity and maximize ultimate recovery.

For many years, commingled production was not been considered as a valid alternative to produce marginal fields due to the complexity associated with it. In the past, a development regulation in many countries did not allow this technique because it could affect the final recovery (J. Ferrer et al., PDVSA Exploration & Production. Commingled Production Well: Experiences in Lake Maracaibo, Venezuela, SPE 49311 New Orleans, USA, September 1998-incorporated herein by reference). However, some new technologies make commingled production a valid alternative to improve the performance of marginal fields. Despite the fact that commingling can make a drastic change in overall field productivity, this decision needs a careful look at some of the parameters in order to have an efficient recovery with minor production problems.

Commingled zones can be two zones, as a simple commingling, and can be as many as 4 zones, and in some cases can be more. However, the more zones are commingled, the more problems are anticipating. Hence, difficulties of well management increase as the number of commingled zones increases. So to have better decision on the commingling, some considerations need to be taken before designing the well. Usually the pay zones at the same formations showed same oil and rock properties as well as production capabilities. So their development strategy is a bit easier and minor production issues were observed. Difficulties appear when there are pay zones in different formations in the same depositional environment area where they are far away from each other. FIG. 2 is an example of a well has 5 pay zones with different properties. In this case usually oil and rock properties will not be the same. In such situations, producing each zone separately might be the optimum decision from a technical point of view.

Before the 1990's, when the horizontal and multi-lateral technology was not available, the only option to produce more than one zone was either to commingle them together or produce them via different tubing string or different wells. Nowadays, you can place a certain number horizontal wells in the thin pay zones in the same field. Also a smart multi-lateral technology can be used to deplete thin pay zones. Although horizontal and multi-lateral technologies have solved most of the commingling issues, still commingling technology in vertical wells is used especially in onshore fields where there are no area limitation and the cost of the drilling and completion is low in comparison to offshore operations. Adding to that, in a very thin pay zone (6-15 ft) where it is better in some cases to produce all zones together rather than place a horizontal or multi-lateral holes on them.

SUMMARY

A system for determining multi-zones commingling in oil field production including: processing circuitry configured to: identify a plurality of zones in a well to be analyzed based on first differences in properties or flow performance, calculate a normalized bubble point pressure, define a first bottom hole flowing pressure for the well; define flowing pressures after excluding the zone with the highest saturation pressure, calculate a normalized bottom-hole flowing pressure and a corresponding flow rate ratio, correlate the Flow Rate Ratio versus the normalized bottom-hole flowing pressure and the flow rate ratio versus the bottom-hole flowing pressure in a Cartesian scale, and determining a feasibility to produce from all of the zones based on saturation pressures of each zone, a relative location of a zone with a highest saturation pressure to the rest of the zones, a relative depth of the s zone with the highest saturation pressure to the rest of the zones, a relative productivity index of the zone with the highest saturation pressure to the rest of the zones.

In one embodiment the normalized bubble point pressure is a first ratio between a second difference in bubble point pressures between two zones that have a highest and a second highest value; to the bubble point pressure for the zone with the highest value.

In another embodiment the bubble point pressure is the pressure below which a two-phase fluid appears in a reservoir or a wellbore.

In another embodiment the two-phase fluid is gas and liquid.

In another embodiment the normalized bottom-hole flowing pressure is a second ratio of a third difference between a second bottom hole flowing pressure if all zones are considered and a third bottom hole flowing pressure if the zone that has the highest saturation pressure value is excluded; to the second bottom hole flowing pressure if all zones are considered.

In another embodiment the flow rate ratio is a third ratio between a first expected flow rate from all zones to a second expected flow rate if that zone with the highest saturation pressure is excluded.

In another embodiment, a possibility of commingling all zones is higher when the saturation pressure of the zone with the highest saturation pressure is closer to the saturation pressure of the rest of the zones.

In another embodiment, the possibility of commingling all zones is higher when the zone with the highest saturation pressure is deeper than the rest of the zones.

In another embodiment, the possibility of commingling all zones is higher when the productivity index of the zone with the highest saturation pressure is greater than the productivity index of the rest of the zones.

In a second aspect the present disclosure includes a method for determining multi-zones commingling in oil field production including: identifying a plurality of zones in a well to be analyzed based on first differences in properties or flow performance; calculating a normalized bubble point pressure; defining a first bottom hole flowing pressure for the well; defining flowing pressures after excluding the zone with the highest saturation pressure; calculating a normalized bottom-hole flowing pressure and a corresponding flow rate ratio; computing the Flow Rate Ratio versus the normalized bottom-hole flowing pressure and the flow rate ratio versus the bottom-hole flowing pressure in a Cartesian scale; determining a feasibility to produce from all the zones based on saturation pressures of each zone, a relative location of a zone with a highest saturation pressure to the rest of the zones, a relative depth of the s zone with the highest saturation pressure to the rest of the zones, a relative productivity index of the zone with the highest saturation pressure to the rest of the zones.

In one embodiment the normalized bubble point pressure is a first ratio between a second difference in bubble point pressures between two zones that have a highest and a second highest value, to the bubble point pressure for the zone with the highest value.

In another embodiment the bubble point pressure is the pressure below which a two-phase fluid appears in a reservoir or a wellbore.

In another embodiment, the two-phase fluid is gas and liquid.

In another embodiment the normalized bottom-hole flowing pressure is a second ratio of a third difference between a second bottom hole flowing pressure if all zones are considered and a third bottom hole flowing pressure if the zone that has the highest saturation pressure value is excluded; to the second bottom hole flowing pressure if all zones are considered.

In another embodiment the flow rate ratio is a third ratio between a first expected flow rate from all zones to a second expected flow rate if that zone with the highest saturation pressure is excluded.

In another embodiment, a possibility of commingling all zones is higher when the saturation pressure of the zone with the highest saturation pressure is closer to the saturation pressure of the rest of the zones.

In another embodiment, the possibility of commingling all zones is higher when the zone with the highest saturation pressure is deeper than the rest of the zones.

In another embodiment, the possibility of commingling all zones is higher when the productivity index of the zone with the highest saturation pressure is greater than the productivity index of the rest of the zones.

In a further aspect the present disclosure includes a non-transitory computer-readable medium including executable instructions, which when executed by a computer processor, cause the computer processor to execute a method including: identifying a plurality of zones in a well to be analyzed based on first differences in properties or flow performance; calculating a normalized bubble point pressure; defining a first bottom hole flowing pressure for the well; defining flowing pressures after excluding the zone with the highest saturation pressure; calculating a normalized bottom-hole flowing pressure and a corresponding flow rate ratio; computing the flow rate ratio versus the normalized bottom-hole flowing pressure and the flow rate ratio versus the bottom-hole flowing pressure in a Cartesian scale; and determining a feasibility to produce from all the zones based on saturation pressures of each zone, a relative location of a zone with a highest saturation pressure to the rest of the zones, a relative depth of the s zone with the highest saturation pressure to the rest of the zones, a relative productivity index of the zone with the highest saturation pressure to the rest of the zones.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a flow chart of determining Multi-zones Commingling in oil field production.

FIG. 2 shows an exemplary well of 5 pay zones.

FIG. 3A shows evaluation plots for the given data of Flow Rate ratio (FRR) versus Normalized Bottom-Hole Flowing Pressure (NPwf).

FIG. 3B shows evaluation plots for the given data of Flow Rate ratio (FRR) versus Bottom-Hole Flowing Pressure (Pwf).

FIG. 4 shows a plot of relation between Flow Rate ratio (FRR) and Normalized Bottom-Hole Flowing Pressure (NPwf) with decreasing Normalized Bubble Point Pressure (NBPP) sensitivity analysis.

FIG. 5 shows a plot of sensitivity analysis of locations of zone 1.

FIG. 6 shows a plot of sensitivity analysis of depths of zone 1.

FIG. 7: shows a plot of flow rate ratio (FRR) and Normalized Bottom-Hole Flowing Pressure (NPwf) sensitivity analysis for different Productivity index (PI) values.

FIG. 8A shows a plot of performance analysis for well A showing of flow rate ratio (FRR) versus normalized bottom-hole flowing pressure (NPwf).

FIG. 8B shows a plot of performance analysis for well A showing of flow rate ratio (FRR) versus Bottom-Hole Flowing Pressure (Pwf).

FIG. 9 shows a schematic diagram of an exemplary processing system.

DETAILED DESCRIPTION OF THE EMBODIMENTS

Commingling is a completion design techniques that has been used in many oil fields (reservoirs) to increase oil production. Simply it is done by opening two zones or more into the well bore such that the two zones flow together. This technique is used mainly when pay zones have similar rock and oil properties. Previously, commingling was done by opening pay zones to the well bore, but recently with the continuing development, commingling is achieved by drilling more than lateral holes into the pay zones from the same main hole, and producing all of them at the same time. Before utilizing commingling, some situations need to be addressed to determine whether all or some of the zones should be commingled together.

In the present disclosure, the effect of some factors on the commingling decision such as critical well bore flowing pressure, saturation pressure, depth and distance between the commingled zones have been addressed. A graphical method is proposed to assist on the commingling decision by evaluating two completion scenarios and analyze both of them graphically. This method is mainly concentrated on the effect of the bubble point pressure as the constraint pressure to the overall well flow, and proposed recommendations in a graphical way. This method is focused mainly on the effect on the bubble point pressure rather than the other factors because it has a major impact on the productions especially if the commingled zones have different values.

It was concluded that commingling becomes more beneficial when the commingled zones have similar saturation pressure; and vice versa. It was also concluded that commingling becomes more beneficial when the zone that has the highest value of saturation pressure is deeper than the rest of the pay zones or has a higher productivity index as compared to the rest of pay zones.

This disclosed method was applied in a case study well that has three zones with different properties. It gave a wide range of solutions based on the bottom hole flowing pressure. It proves that this method can be considered as one of the evaluation tools during the phase of completion design to answer many questions with regard to the commingling strategy.

In the present disclosure a simple and efficient graphical method is disclosed from which is can be determined whether all pay zones have to be commingled or whether one or some of the pay zones need to be developed separately. First of all, the effect of some of the important parameters of the commingling decision is disclosed such as critical bottom hole flowing pressure, distance between zones, rock properties, crude oil properties especially saturation pressure.

Referring to FIG. 1, a flow chart 100 describing a method for determining multi-zones commingling in oil field production is presented.

In step 102, the processing circuitry determines which zone or zones should be analyzed based on the differences in properties or flow performance. In case two or more zones are selected for the analysis, each zone should be analyzed separately if their properties are significantly different. If the selected zones have similar properties, analysis will be done together.

In step 104, normalized bubble point pressure using the known saturation pressures for the pay zones is calculated.

In step 106, a bottom hole flowing pressure for all the pay zones is defined, note that this pressure depends on the zone that has the highest value of saturation pressure.

In step 108, flowing pressures after excluding the zone with the highest saturation pressure is defined.

In step 110, a normalized bubble point pressure and the corresponding flow rate ratio values are calculated.

In step 112, the flow rate ratio values versus normalized bubble point pressure and flow rate ratio versus flowing bottom-hole pressure in a Cartesian scale are correlated.

In step 114, the flowing bottom-hole pressure value that is feasible to produce from all zones or the zone with the highest saturation pressure should not be considered in the completion and need to be completed separately is determined.

Borehole instability and sand production are significant problems confronting the petroleum industry. Sand production is a natural consequence of fluid flow into a wellbore from the reservoir. The process may be divided into the following stages: the loss of mechanical integrity of the rocks surrounding an open hole or perforation, separation of solid particles from the rocks due to hydrodynamic force and transportation of the particles to the surface by reservoir fluids.

According to Plamer et al., (“Allowable Drawdown Pressure for Fracpack in Mahogany field, Gulf of Mexico”, Exploration & Production Technology Group, 1999—incorporated herein by reference) critical drawdown pressure (CDP) is defined as the maximum drawdown pressure before sand production from formation begins. CDP is depending on many factors such as: overburden pressure, pore pressure, horizontal stresses and reservoir characteristics. Currently there are many studies have been done to estimate CBHFP and CDP. These studies were based on measuring rock mechanical properties such as poisson's ratio, unconfined compressive strength (UCS), collapse strength and horizontal stresses (minimum and maximum).

It is important to estimate the CBHFP for each zone to avoid failure of the formation near the well bore. A laboratory tests need to be conducted for each field to estimate CBHFP; however, studies showed that CBHFP is ranging from 0.5-0.6% of the pore pressure for the consolidated formations; if the pore pressure remains constant with the help of pressure maintenance methods. CBHFP in unconsolidated formations can be as high as 0.7% of the pore pressure.

When commingling two or more zones, it is very important that to keep the well bore pressure above the CBHFP of the zone that have the maximum value. In this case, if one zone has high CBHFP with regard to the rest of the zones, it may be better to produce this zone separately to allow high drawdown from the other layers. Fortunately this factor does not play a major role in the commingling decision as most of the layers at the same basin have the same pressures trend.

Saturation Pressure Bubble Point Pressure (BPP) is defined as the pressure below which you are going to have two-phase fluids “i.e. gas and liquid” either in the reservoir or in the wellbore. Its value depends mainly on the components of the hydrocarbon and the amount of gas in solution.

Saturation pressure is very important when determining a production strategy for a field. The bottom hole flowing pressure should be greater that the saturation pressure with some safety factor. So the bottom hole flowing pressure constraint “BHPC” is controlled with the following equation as defined in Obeida et al., (“Calculation of Flowing Optimum Bottom-hole Pressure Constraint Based on Bubble point-Pressure-vs-Depth Relationship. SPE 107058 paper presented in London, UK, June 2007—incorporated herein by reference).

BHPC=P _(b)+SF  (1)

where BHPC is bottom-hole pressure constraint, P_(b) is bubble point or saturation pressure, SF is certain value used as a safety factor.

Safety factor varies from one area to another and can be defined based on the crude properties and experience. The lower the safety factor, the more challenges will be faced. Normally for fields with high saturation pressure, the safety factor should be as higher as compared with the fields with low saturation pressure.

The situation becomes complicated when dealing with multi-zone production especially with variations in saturation pressure between pay zones. The key point is to avoid having two phase flow inside the reservoir because this will create a lot of complexity when it comes to the reservoir management. Due to that, it is very important to check whether it is technically and economically feasible to flow all the pay zones together or whether it is required to produce all the pay zones concurrently or some of them separately. Technically it is better to complete each zone alone in order to have better monitoring and management of the field. The final determination is reached by looking from all the angles, especially economics. Based on that, commingling all or some of the pay zones comes into play. Nowadays, it is normal to find wells producing from more than one zone.

Although the depth of the pay zones does not play a direct role in the commingling decision, it has an indirect effect on the decision. Depth affects indirectly the rock and fluid properties especially if the pay zones are considerably far away. As an example, with two pay zones, one at a depth of 3000 ft and the other one at 6000 ft, the shallow zone will be more unconsolidated and have different fluid properties as compared to the bottom one. So we are going to have a restriction in the well bore flowing pressure that can lead to low production if we commingle them together.

A key point is that the depth and distance between the commingled zones creates a pressure drop due to gravity and friction. Wellbore flowing pressure after this drop must be within the limit of the zone that has an issue with the minimum flowing pressure. Also the wellbore flowing pressure must be greater than the saturation pressure “bubble point pressure” of the zone that has the highest value. So it is really important to make a good estimation of well bore pressure before the commingling decision in order not to end up with a problematic well.

These conditions make it clear that the decision whether to commingle is complicated. A graphical method to assist in the commingling determination is disclosed herein. The method takes into account all the above mentioned parameters to come up with a good well design.

The disclosed graphical method for the determining commingling depends on analyzing rock and crude oil properties as well as the reservoir capabilities. The method provides results graphically that can be easily read and used. The method is disclosed for up to three zones only, but based can be applied for more than three zones. Some assumptions were made to reflect the original situation of most of the fields at their early lifetimes. These assumptions are: No or negligible water production, no or negligible multiphase flow in the well bore up to the top of the shallowest zone; use of OPR (Outflow Performance) equations to calculate the pressure drop from the deeper zones up to the shallowest zone, and all zones are normally pressured and no cross-flow between them. Below are some definitions and equations used in the method:

Normalized Bubble Point Pressure (NBPP) is the ratio between the difference in bubble point pressures between the two zones that have the highest and the second highest value; to the bubble point pressure for the zone with the highest value. Mathematically:

$\begin{matrix} {{N\; B\; P\; P} = \frac{{B\; P\; P_{h\; 1}} - {B\; P\; P_{h\; 2}}}{B\; P\; P_{h\; 1}}} & (2) \end{matrix}$

Where BPP_(h1) is Bubble point pressure in the zone that has the highest value, BPP_(h2) is Bubble point pressure in the zone that has the second highest value.

Normalized Bottom-Hole Flowing Pressure (NPwf) is the ratio of the difference between the bottom hole flowing pressure if all pay zones are considered and the bottom hole flowing pressure if the pay zone that have the highest saturation pressure value is excluded; to the bottom hole flowing pressure if all zones are considered. Mathematically:

$\begin{matrix} {{N\; P\; w\; f} = \frac{{Pwf}_{all} - {Pwf}}{{Pwf}_{all}}} & (3) \end{matrix}$

where Pwf_(all) is flowing bottom hole pressure if all zones are considered, Pwf is flowing bottom hole pressure if the zone with the highest saturation pressure is excluded.

Flow Rate Ratio (FRR) is the ratio between the expected flow rates from all zones to the expected flow rate if that zone with the highest saturation pressure is excluded. Mathematically:

$\begin{matrix} {{F\; R\; R} = \frac{Q_{all}}{Q}} & (4) \end{matrix}$

Where Q_(all) expected flow rate from all the zones, Q is Expected flow rate if the zone with the highest saturation pressure is excluded. Q is calculated using normal IPR and OPR equations. Q_(all) is calculated using a similar method proposed by Tabatabaei et al., (“A New Method To Predict Performance Of Horizontal and Multilateral Wells, SPE IPTC 13122, Proceedings of the International Petroleum Technology Conference, 7-9 Dec., 2009, Doha, Qatar-incorporated herein by reference) for the well performance of horizontal and multi-lateral wells.

The methodology of the analysis is as below: decide which zone or zones need to be analyzed based on the differences in properties or flow performance, when two or more zones are selected for the analysis, each zone should be analyzed separately if their properties are far different, if the selected zones have similar properties, analysis is carried out together; calculate NBPP using the known saturation pressures for the pay zones; define the bottom hole flowing pressure for all the pay zones, note that this pressure depends on the zone that has the highest value of saturation pressure; define the flowing pressures after excluding the zone with the highest saturation pressure; calculate the NPwf and the corresponding FRR values; correlate FRR versus NPwf and FRR versus Pwf in a Cartesian scale; for the Pwf for the production zone determine whether it is feasible to produce from all zones or the zone with the highest saturation pressure should not be considered in the completion and need to be completed separately. Plotting can include forming a graphical representation or may occur in a processor without formation of a diagram.

To illustrate more on the above proposed procedure and the effect of some parameters on the commingling decision, the data in Table I was used to represent a typical commingling situation. On top of the above mentioned assumptions, assumptions below are also made to ease the calculation and comparison: Two zones have similar saturation pressure, and the third one has higher value than the other two, all zones have similar productivity index, flowing pressure is greater than the saturation pressure by 150 psia as a safety factor.

TABLE I Parameter Zone 1 Zone 2 Zone 3 Depth, ft 6000 6100 6200 Reservoir Pressure, psia 2598 2641 2685 BPP, psia 2000 500 500 PI, STB/D/psia 1.0 1.0 1.0 Viscosity, cp 1.0 1.0 1.0 SG, fraction 0.85 0.85 0.85 Well ID, inches 6.184 6.184 6.184

FIG. 3 a shows the relation between FRR and NPWF. FIG. 3 b shows the relation between FRR and PWF. The plot suggested that at FRR=1.0 and NPwf=0.08 (Pwf=1975 psia), similar production whether all zones are completed or if zone 1 is not considered in completion. So, if the decision is to flow the well with this pressure, it is recommended to complete all the pay zones together. Due to the fact that there is no constraint in pressures for the other two zones and critical flowing pressure is assumed to be 1000 psi, production from all zones will be less than production if zone 1 excluded and produced with flowing pressure less than 1975 psia. In other words, if a production of 1363 bbls/d from all zones with the current situation is expected, production can be as high as 3375 bbls/d at Pwf=1000 psia when zone 1 is excluded from the completion strategy. So from the above two figures, decision can be made based on the required bottom-hole flowing pressure.

Following sensitivity analysis studies have been done for to evaluate their effect on the commingling decision: Saturation pressures of the selected pay zones, location of zone 1 with regard to the other zones, the depth of zone 1 with regards to the other pay zones and the productivity index (PI) of zone 1.

FIG. 4 shows the relation between FRR and NPwf for the above data and allowing the saturation pressure for zone 1 to be decreased to assess the relation. Relation suggests that as the saturation pressure of zone 1 gets closer and closer to the value for zone 2 & zone 3, most likely commingling all zones is more viable.

FIG. 5 shows the sensitivity analysis for the location of zone 1 with regards to zone 2 and zone 3. The plot showed that the curve is shifted to the right which means the possibility of commingling all zones become higher when zone 1 is deeper than the other zones.

FIG. 6 represents the sensitivity analysis for the depth of zone 1 and allows its depth to be shallowed by 1000 ft and deepened by 1000 ft from the base depth. It is clear that when zone 1 is deeper, the curve will be moved up. So the decision for commingling will become stronger if zone 1 is deeper than the other zones.

FIG. 7 represents the sensitivity analysis for the productivity index (PI) for the three zones assuming that zone 1 has PI of 25%, 50%, 100%, 150% & 200% of the PI of zone 2 or zone 3.

FIG. 7 clearly that to consider commingling all zones, one should have NPwf≦0.18 (Pwf≧1750 psia) for the case of 200%, NPwf≦0.14 (Pwf≧1850 psia) for the case of 150%, NPwf≦0.08 (Pwf≧1975 psia) for the case of 100%, NPwf≦0.035 (Pwf≧2075 psia) for the case of 50% and NPwf≦0.015 (Pwf≈2150 psia). In other words, commingling becomes more viable when the productivity index of the zone with higher saturation pressure is greater than the rest of the pay zones.

The following describes a case study using the proposed embodiment. Well A is a vertical well drilled with a total depth of 5906 ft. This well penetrated three main reservoirs with different rock and oil properties. Table II includes the data from well A. Rock and fluid properties are as the following:

TABLE II Property Zone 1 Zone 2 Zone 3 Formation Type Sandstone Sandstone Sandstone Distance to Mid zone, ft 4390.0 5156.1 5292.3 Reservoir Pressure, psia 1984 2144 2183 Reservoir temperature, C. 62.2 70.0 71.1 Saturation Pressure, psia 1597 296 130 API Gravity 31.5 27.0 23.7 GOR, SCF/STB 184 32.9 11.2 Oil viscosity, cp 9.5 28.0 58.0 Bo, RB/STB 1.10 1.04 1.03 Productivity Index (PI) 5.1 0.92 3.5

All pay zones were perforated to be produced together. Critical bottom hole flowing pressure was set to be 1000 psia (which will play as a constrained flow pressure for this case). Bottom hole flowing pressure should be greater than the saturation pressure by at least 150 psia.

Based on the above information, flow capacity analysis is being done for these zones to evaluate the decision that was made to commingle all zones. Normalized bubble point pressure for this well is calculated to be: NBPP=0.709.

For this NBPP, Value of NPwf and corresponding FRR is being calculated. A plot of FRR versus NPwf & FRR versus Pwf is being generated as shown in FIG. 8.

From FIG. 8, at FRR=1.0, NPwf=0.06 (Pwf=1650 psia). At this value, if production is only from zone 2 & zone 3, it will be equal to the production from all three zones with the constrained production (1030.0 STB/D at Pwf=1750 psia). Based on the well performance, it seems that the saturation pressure of zone 1 acts as a production constraint. Excluding this zone from the completion design and flow the well with pressure near to the critical flowing pressure, is a better decision because the daily production can be as high as 2250 STB/D at Pwf=1100 psia.

In case of this well, the best decision is either to design the well based on dual completion to produce zone 1 separately and zone 2 and zone 3 together, or drill new a well to produce zone 1 alone and commingle zone 2 & zone 3 together. In this case the production will be 2250 STB/D at 1100 psia from zone 2 and zone 3, and around 750 STB/D at 1750 psia form zone 1. Of course whether to produce these zones from the same well or different wells will depend on the economic studies together with the technical aspects. Also productivity index for zone 1 can be increased if a horizontal well is placed on that zone.

The decision to commingle two zones or more is a challenging decision especially when pay zones have had different rock and oil properties. The new graphical method (Barri & Nuaim) assists in the commingling decision. The method is helpful and can be used as a quick look tool to assist in the completion design strategy. The method provides suggestions for the completion strategy when there are differences in productivity indices, distances between zones and oil properties especially the saturation pressure of the oil of each pay zone. The method can evaluate two scenarios; commingling all zones or excluding zone(s) that has (have) a constraint condition. Then method analyzes them together to decide which scenario is the best based on the required production strategy. The method showed that when saturation pressures of the commingled zones are similar, it is more likely to commingle them together. Furthermore, if the zone with the highest saturation pressure value located deeper than the other zones, commingling decision possibility becomes stronger.

Next, a hardware description of the processing circuitry according to exemplary embodiments is described with reference to FIG. 9. In FIG. 9, the processing circuitry includes a CPU 900 which performs the processes described above. The process data and instructions may be stored in memory 902. These processes and instructions may also be stored on a storage medium disk 904 such as a hard drive (HDD) or portable storage medium or may be stored remotely. Further, the claimed advancements are not limited by the form of the computer-readable media on which the instructions of the inventive process are stored. For example, the instructions may be stored on CDs, DVDs, in FLASH memory, RAM, ROM, PROM, EPROM, EEPROM, hard disk or any other information processing device with which the processing circuitry communicates, such as a server or computer.

Further, the claimed advancements may be provided as a utility application, background daemon, or component of an operating system, or combination thereof, executing in conjunction with CPU 900 and an operating system such as Microsoft Windows 7, UNIX, Solaris, LINUX, Apple MAC-OS and other systems known to those skilled in the art.

CPU 900 may be a Xenon or Core processor from Intel of America or an Opteron processor from AMD of America, or may be other processor types that would be recognized by one of ordinary skill in the art. Alternatively, the CPU 900 may be implemented on an FPGA, ASIC, PLD or using discrete logic circuits, as one of ordinary skill in the art would recognize. Further, CPU 900 may be implemented as multiple processors cooperatively working in parallel to perform the instructions of the inventive processes described above.

The processing circuitry in FIG. 9 also includes a network controller 906, such as an Intel Ethernet PRO network interface card from Intel Corporation of America, for interfacing with network 99. As can be appreciated, the network 99 can be a public network, such as the Internet, or a private network such as an LAN or WAN network, or any combination thereof and can also include PSTN or ISDN sub-networks. The network 99 can also be wired, such as an Ethernet network, or can be wireless such as a cellular network including EDGE, 3G and 4G wireless cellular systems. The wireless network can also be WiFi, Bluetooth, or any other wireless form of communication that is known.

The processing circuitry further includes a display controller 908, such as a NVIDIA GeForce GTX or Quadro graphics adaptor from NVIDIA Corporation of America for interfacing with display 910, such as a Hewlett Packard HPL2445w LCD monitor. A general purpose I/O interface 912 interfaces with a keyboard and/or mouse 914 as well as a touch screen panel 916 on or separate from display 910. General purpose I/O interface also connects to a variety of peripherals 918 including printers and scanners, such as an OfficeJet or DeskJet from Hewlett Packard.

A sound controller 920 is also provided in the processing circuitry, such as Sound Blaster X-Fi Titanium from Creative, to interface with speakers/microphone 922 thereby providing sounds and/or music.

The general purpose storage controller 924 connects the storage medium disk 904 with communication bus 926, which may be an ISA, EISA, VESA, PCI, or similar, for interconnecting all of the components of the processing circuitry. A description of the general features and functionality of the display 910, keyboard and/or mouse 914, as well as the display controller 908, storage controller 924, network controller 906, sound controller 920, and general purpose I/O interface 912 is omitted herein for brevity as these features are known. 

1. A method for determining multi-zones commingling in oil field production comprising: identifying a plurality of zones in a well to be analyzed based on first differences in properties or flow performance; calculating a normalized bubble point pressure for the zones; defining a first bottom hole flowing pressure for the well; defining flowing pressures for each zone after excluding the zone with the highest saturation pressure; calculating a normalized bottom-hole flowing pressure and a corresponding flow rate ratio for the well; correlating the flow rate ratio versus the normalized bottom-hole flowing pressure and the flow rate ratio versus the bottom-hole flowing pressure in a Cartesian scale; determining a feasibility to produce from all of the zones based on saturation pressures of each zone, a relative location of a zone with a highest saturation pressure to the rest of the zones, a relative depth of the s zone with the highest saturation pressure to the rest of the zones, a relative productivity index of the zone with the highest saturation pressure to the rest of the zones.
 2. The method of claim 1, wherein the normalized bubble point pressure is a first ratio between a second difference in bubble point pressures between two zones that have a highest and a second highest value, to the bubble point pressure for the zone with the highest value.
 3. The method of claim 2, wherein the bubble point pressure is the pressure below which a two-phase fluid appears in a reservoir or a wellbore.
 4. The method of claim 3, wherein the two-phase fluid is gas and liquid.
 5. The method of claim 1, wherein the normalized bottom-hole flowing pressure is a second ratio of a third difference between a second bottom hole flowing pressure if all zones are considered and a third bottom hole flowing pressure if the zone that has the highest saturation pressure value is excluded; to the second bottom hole flowing pressure if all zones are considered.
 6. The system of claim 1, wherein the flow rate ratio is a third ratio between a first expected flow rate from all zones to a second expected flow rate if that zone with the highest saturation pressure is excluded.
 7. The method of claim 1, wherein a possibility of commingling all zones is higher when the saturation pressure of the zone with the highest saturation pressure is closer to the saturation pressure of the rest of the zones.
 8. The method of claim 1, wherein the possibility of commingling all zones is higher when the zone with the highest saturation pressure is deeper than the rest of the zones.
 9. The method of claim 1, wherein the possibility of commingling all zones is higher when the productivity index of the zone with the highest saturation pressure is greater than the productivity index of the rest of the zones.
 10. A system for determining multi-zones commingling in oil field production comprising: processing circuitry configured to: identify a plurality of zones in a well to be analyzed based on first differences in properties or flow performance; calculate a normalized bubble point pressure; define a first bottom hole flowing pressure for the well; define flowing pressures after excluding the zone with the highest saturation pressure; calculate a normalized bottom-hole flowing pressure and a corresponding flow rate ratio; compute the Flow Rate Ratio versus the normalized bottom-hole flowing pressure and the flow rate ratio versus the bottom-hole flowing pressure in a Cartesian scale; and determine a feasibility to produce from all the zones based on saturation pressures of each zone, a relative location of a zone with a highest saturation pressure to the rest of the zones, a relative depth of the s zone with the highest saturation pressure to the rest of the zones, a relative productivity index of the zone with the highest saturation pressure to the rest of the zones.
 11. The system of claim 10, wherein the normalized bubble point pressure is a first ratio between a second difference in bubble point pressures between two zones that have a highest and a second highest value; to the bubble point pressure for the zone with the highest value.
 12. The system of claim 11, wherein the bubble point pressure is the pressure below which a two-phase fluid appears in a reservoir or a wellbore.
 13. The system of claim 12, wherein the two-phase fluid is gas and liquid.
 14. The system of claim 10, wherein the normalized bottom-hole flowing pressure is a second ratio of a third difference between a second bottom hole flowing pressure if all zones are considered and a third bottom hole flowing pressure if the zone that has the highest saturation pressure value is excluded; to the second bottom hole flowing pressure if all zones are considered.
 15. The system of claim 10, wherein the flow rate ratio is a third ratio between a first expected flow rate from all zones to a second expected flow rate if that zone with the highest saturation pressure is excluded.
 16. The system of claim 10, wherein a possibility of commingling all zones is higher when the saturation pressure of the zone with the highest saturation pressure is closer to the saturation pressure of the rest of the zones.
 17. The system of claim 10, wherein the possibility of commingling all zones is higher when the zone with the highest saturation pressure is deeper than the rest of the zones.
 18. The system of claim 10, wherein the possibility of commingling all zones is higher when the productivity index of the zone with the highest saturation pressure is greater than the productivity index of the rest of the zones.
 19. A non-transitory computer-readable medium including executable instructions, which when executed by a computer processor, cause the computer processor to execute a method comprising: identifying a plurality of zones in a well to be analyzed based on first differences in properties or flow performance; calculating a normalized bubble point pressure; defining a first bottom hole flowing pressure for the well; defining flowing pressures after excluding the zone with the highest saturation pressure; calculating a normalized bottom-hole flowing pressure and a corresponding flow rate ratio; computing the flow rate ratio versus the normalized bottom-hole flowing pressure and the flow rate ratio versus the bottom-hole flowing pressure in a Cartesian scale; and determining a feasibility to produce from all the zones based on saturation pressures of each zone, a relative location of a zone with a highest saturation pressure to the rest of the zones, a relative depth of the s zone with the highest saturation pressure to the rest of the zones, a relative productivity index of the zone with the highest saturation pressure to the rest of the zones. 